The lowdown on hydrogen – part 2: production

Electrolysis, powered by renewables, is often seen as the ideal way to produce hydrogen. But electrolysis is expensive and not always efficient, writes Roger Arnold. There are other ways that are more efficient and also climate friendly. This is part 2 of a two-part series on hydrogen written by independent energy expert Roger Arnold. Part 1 deals with the uses of hydrogen in transport.

In part 1 last week, I reviewed current status and issues surrounding battery vs. fuel cell electric vehicles. There’s more to be said about that, but not just now. My overall aim here is to explore and clarify — for myself as much as anyone — issues around electricity and hydrogen in a sustainable clean energy economy. In particular, I’d like to understand the significance of the apparent resurgence of interest in fuel cells and the “hydrogen economy”. Toward that end, I think the next order of business is to look at options for hydrogen production. There are new possibilities that I only recently learned about that may prove significant.

What’s wrong with electrolysis?

There are many ways to produce hydrogen. There are only two, however, that are commercially significant in the US and most other nations. One is steam methane reforming (SMR), which starts with natural gas as feedstock. The other is electrolysis of water.

Inputs for electrolysis are just electricity and water. If the electricity is from carbon-free renewable resources, the resulting hydrogen is also carbon-free. That makes electrolysis very attractive to renewable energy advocates. It’s seen as a way to make use of excess power and stabilize the grid when wind and solar resources are making more power than the grid can otherwise absorb.

The larger issue for renewable energy is undersupply, not oversupply

It can certainly do that. And producing hydrogen by electrolysis is more valuable than curtailing power production or dissipating it in a resistor bank when there is truly excess supply. However the larger issue for renewable energy is undersupply, not oversupply. When the sun isn’t shining and the wind isn’t blowing, there’s still demand to be met. There needs to be a way to meet it. If it’s not dispatched fossil fuels, it has to be energy drawn from storage.

Hydrogen does in fact make it feasible to store enough energy to meet demand during lulls. Even extended lulls. The problem is that it’s inherently expensive. That matters, because solutions that cost more don’t get adopted when there are cheaper alternatives available. And dispatching fossil fuel generators is a cheaper alternative that is definitely available.

So why is electrolytic hydrogen inherently expensive? If the electricity driving the electrolysis is surplus, to the point that the alternative to electrolysis is curtailment, the cost of that electricity should be almost nothing. Won’t the hydrogen produced also be very cheap?

Well, it would be, if the capital cost of the electrolysis equipment were negligible, or if renewable energy available for “almost nothing” were common enough to power the equipment at a decent duty cycle. Neither of those conditions applies, however.

The fraction of delivered power that stored hydrogen would need to supply depends strongly on what other resources are online and what level of demand side management has been implemented. In the conceptually appealing but economically worst case scenario of 100% wind and solar, no demand side management, and no super transmission systems, energy from stored hydrogen would represent about three quarters of all kilowatt-hours delivered.

In any system where a substantial fraction of delivered kilowatt-hours must come from storage, the very poor round-trip energy efficiency of power-to-gas-to-power bites hard

That’s of course not very realistic, since even a 100% renewables scenario will include a degree of dispatchable hydroelectric, some demand side management, and a transmission system sufficient to provide partial statistical leveling of wind and solar availability. Even so, with no baseload supply and no resort to dispatched fossil generation, stored hydrogen would need to provide at least a quarter of kilowatt-hours delivered in most cities below 40 degrees latitude. At higher latitudes, seasonal variation in solar availability would raise the figure.

In any system where a substantial fraction of delivered kilowatt-hours must come from storage, the very poor round-trip energy efficiency of power-to-gas-to-power bites hard. 40% is usually taken as the highest round-trip efficiency one could expect for a PEM electrolyzer – fuel cell combination.

If the gas-to-power side employs simple gas combustion turbines rather than fuel cells — as might be the case for generating occasional high power output from a central facility near a gas storage cavern — the round trip efficiency could easily be under 30%. But even at an optimistic 40%, 2.5 kilowatt-hours of input energy would be needed for every kilowatt-hour of energy delivered from storage.

If energy delivered from storage were 25% of energy consumed, then total energy produced would need to increase by three eighths (37.5%) to cover round trip energy losses for that 25%. Renewable energy production at 137.5% of total load would divide as 75% to direct service of load and 62.5% dedicated to hydrogen production for energy storage.

The numbers get rapidly worse if one assumes less than 40% round trip efficiency or greater than 25% of load supplied from stored energy. That doesn’t actually matter to the bottom line, however. The bottom line is that if coping with intermittency of supply in a 100% renewable energy economy were to be based on electrolysis of water, electrolysis would represent by far the largest load on the system. It could not run on “almost free” surplus energy, because there would be none.

The electrolysis load would consume every bit of power output not required by higher priority loads, and still need more. It could go offline at times of shortage, thus avoiding peak charges. But it could never get by on “almost free” surplus power. It would have to pay at the full rate needed to amortize the capital and operating expenses of the renewable energy systems dedicated to feeding it.

Prospects for improvement?

What about prospects for better efficiency in the future? The theoretical potential is always there, but near-term practical prospects look poor. A good part of the inefficiency that besets water electrolyzers and hydrogen fuel cells is “semi-fundamental”. It’s rooted in the substantial overpotential associated with the oxygen evolution reaction (in electrolyzers) and its inverse (in fuel cells).

The overpotential for the oxygen reactions is analogous to the forward voltage drop across a P-N diode junction. At any positive forward bias, the P-N diode junction should theoretically conduct some current. And in fact one can observe that it does — given a sufficiently sensitive lab setup. The current is exponential with voltage, but the knee of the curve doesn’t show up until the forward bias rises above about 0.6 to 0.7 volts.

Historically, the cost of hydrogen from SMR has averaged roughly a quarter to a third of the cost of hydrogen from electrolysis

In a similar manner, an electrolysis cell will evolve tiny amounts of hydrogen and oxygen at any cell voltage above the 1.23 volt equilibrium voltage of water at ambient temperature. But the amounts will be too tiny to notice until the cell voltage rises above about 1.7 volts. Conversely, a hydrogen fuel cell won’t produce a noticeable current against a cell voltage higher than about 0.8 volts.

The required overpotential can be reduced considerably at high temperatures — meaning in this case upwards of 500 ℃. “Steam electrolysis”, a cousin to solid oxide fuel cell technology, has long been of interest as a more efficient way to split water. But it’s never been successfully commercialized. The problem has been poor durability of the ceramic electrolyte in a hot hydrogen environment. I’ve seen no indications of that being about to change.

Steam methane reforming

If hydrogen can’t be produced cheaply by electrolysis in quantities large enough to be useful for grid-scale energy storage — much less for a major transportation fuel — what about other production methods? What about steam methane reforming?

The cost of hydrogen from SMR is linked to the cost of natural gas. But so, increasingly, is the cost of electricity. Historically, the cost of hydrogen from SMR has averaged roughly a quarter to a third of the cost of hydrogen from electrolysis. That’s in line with what one might expect, given that it takes nearly three units of natural gas, on average, to produce one unit of electricity, while the energy efficiency of electricity to hydrogen is worse than that of natural gas to hydrogen.

With that much of a cost difference, it’s no surprise that SMR supplies 95% of the market for hydrogen used in oil refining and other industries. Hydrogen from electrolysis is only used when the quantities needed are small or the purity requirements exceptionally high.

The downside of hydrogen from SMR is that natural gas is a fossil fuel, and the prevailing methods of implementing SMR vent fossil carbon into the atmosphere. That’s because the primary reaction:

CH₄ + H₂O + heat ⇌ CO + 3H₂

is strongly endothermic; it requires heat to drive it forward. That heat is usually supplied by burning some of the natural gas, producing CO₂. The CO in the output stream from the primary reaction is usually also converted to CO₂ via the water gas shift reaction:

CO + H₂O ⇌ CO₂ + H₂ + heat

There are many ways to engineer the reaction train for SMR. In most cases a waste stream of CO₂ and N₂ (from the air used in burning some of the gas) is produced. The mixture is usually vented. However, in situations where a pure CO₂ stream has value, it can be arranged at little added cost. Either the CO₂ can be separated out, or the reaction train can be engineered so that atmospheric N₂ never enters the gas flow in the first place.

There is an existing market for CO₂ that is already fairly large. If it develops as many expect over the next few decades, it will be large enough to absorb the CO₂ supply from even large scale production of hydrogen by SMR

A good technical presentation from the Colorado School of Mines covers several variations for SMR trains. It’s not exhaustive; there are significant variations that it doesn’t cover, including a new one recently announced that promises to make clean SMR with a pure CO₂ waste stream practical at the scale of a hydrogen refueling station. The capital cost would be low. The station would need to be located near a CO₂ pipeline to facilitate disposal of the CO₂, but that’s not impossible.

The low cost of producing hydrogen from natural gas, along with the relative ease of producing a “pipeline ready” CO₂ waste stream, mean that carbon-free hydrogen could in fact be supplied to fuel cell vehicles at a cost below the equivalent amount of gasoline.

Disposal of CO₂

If we should use SMR to produce cheap hydrogen for FCVs, how will we dispose of the CO₂? And how will disposal affect the cost of the hydrogen produced? It’s a non-trivial question.

Given the slow turnover rate in the automotive vehicle fleet, it can take a decade or two for even the most favorable new technologies to permeate the fleet. In view of that, the amount of CO₂ associated with hydrogen production for FCVs is unlikely to become significant any time soon. There are commercial uses for small quantities of CO₂ that are not controversial. That market is probably large enough to absorb the supply of CO₂ from hydrogen production for the automotive market for at least the next ten years. Beyond that — and especially if hydrogen is adopted for backing renewables on the electricity grid — larger markets for CO₂ will have to be tapped.

There is an existing market for CO₂ that is already fairly large. If it develops as many expect over the next few decades, it will be large enough to absorb the CO₂ supply from even large scale production of hydrogen by SMR. But it’s not without controversy. It’s the market for CO₂ based Enhanced Oil Recovery (EOR).

CO₂ based EOR involves pumping of compressed CO₂ through injection wells to an oil-bearing formation. It restores pressure in the formation and forces remaining oil toward production wells. It also mixes with the oil, expanding its volume and reducing its viscosity. That enables it to flow more easily through the porous rock of the oil reservoir. As explained in this document from the Global CCS Institute, injection of CO₂ into mature oil fields is increasingly considered the most effective method available to revive output and keep the fields producing.

With the oil age drawing to a necessary close, it makes sense to capitalize on the desire of incumbent producers to maintain their positions for as long as demand holds. By getting the most out of old wells, we can undercut the market for new wells

The controversy around CO₂ based EOR is at multiple levels. It recovers oil from mature fields that would not otherwise be recoverable. Many object to it on that basis alone. They feel that oil should be left in the ground, and that any technology that allows more of it to be recovered must to opposed. But that position rests on an implicit assumption that we will ultimately burn all the oil that is recoverable, and that technology to increase what can be recovered will increase what will be released into the atmosphere.

If we expect to leave a habitable world for future generations, we will have to stop well short of burning all the oil that is recoverable. But in that case, it doesn’t ultimately matter if technology makes more of the oil from mature oil fields recoverable. That only affects who will produce whatever oil we end up burning, and where it will be produced. We’ll stop before it’s all gone, because we have to.

In that case, with the oil age drawing to a necessary close, it makes sense to capitalize on the desire of incumbent producers to maintain their positions for as long as demand holds. By getting the most out of old wells, we can undercut the market for new wells while disposing of large amounts of CO₂ in the bargain.

Other objections to CO₂ based EOR have to do variously with doubts about safety, duration of sequestration, and economic viability. Those are large topics, and I won’t try to address them in any detail in this post. However, CO₂ based EOR is not a new thing, and oil and gas industry has decades of experience with it on which to draw.

In fact, there are already some 3600 miles of pipeline in North America for transporting CO₂ from various sources to EOR sites. The map below, from an NETL review of CO₂ pipeline infrastructure in the US, shows the pipelines and CO₂ sources as of 2014, and the oil field regions served.

Notably absent are the oil fields of Kern County and southern California. The nature of those fields makes them good candidates for CO₂ EOR, but there is no large natural CO₂ source nearby that would make a pipeline network to the fields attractive to investors. There are certainly many industrial facilities that could be equipped for carbon capture. If a CO₂ pipeline ran near them, they could connect to it and profit from sale of their captured CO₂. However, none has been large enough to anchor construction of a pipeline. So it hasn’t happened.

Byproduct carbon black from methane cracking could become the ultimate stored energy resource. Stores of terawatt-hours of energy could easily be accumulated

It’s possible that the State of California, if it came to see SMR with carbon capture as the most practical route to success of zero-emission hydrogen FCVs, might do something about that. It could offer loan guarantees for construction of the pipeline, along with the SMR plants that would feed it. Disposal of CO₂ would then reduce, not increase, the cost of hydrogen fueling stations that the state wants to see. If I were an executive at Toyota, Honda, or Hyundai, I’d be enrolling oil field operators and directing lobbyists in Sacramento to promote that idea.

Beyond SMR

There might be another way to produce hydrogen from natural gas that would obviate the need for disposal of CO₂. That’s by cracking methane (and other volatile hydrocarbons in natural gas) to produce pure carbon and hydrogen. It’s a high temperature reaction that is very familiar to chemical engineers. It’s even used commercially to produce carbon black for use in tires and other rubber products. But the method used to drive the reaction has been a plasma arc. That approach is extremely energy intensive.

A few research groups have been exploring other approaches that would be much more efficient. The most promising alternative may be one that was reported in the cover article in an August 2016 issue of New Scientist. It was dramatically titled “The Reaction that Will Change the World”. It involves bubbling natural gas through molten tin at ~1000 ℃. Carbon from the natural gas splits from its hydrogen atoms and dissolves into the tin. The orphaned hydrogen bubbles to the top of the pool, where it’s separated from any unreacted methane through a hydrogen permeable membrane. The unreacted methane is recycled. The dissolved carbon, meanwhile, precipitates as microparticles of carbon black that migrate to the surface of the pool. Accumulated carbon black can be scraped from pool of tin in the same manner as slag from a pool of molten steel.

The process only produces half as much hydrogen per unit of natural gas as SMR, but it does so with high energy efficiency. There is no CO₂ needing to be transported by pipeline and pumped into geological storage reservoirs far underground. The waste stream is fine carbon black that has many potential uses. High value uses would be in water and air filters (in place of activated charcoal) and as filler material in tires and in rubber and plastic products.

It does seem to me that the idea of clean hydrogen from chemical processing of fossil fuels offers game-changing potential

If implemented to supply hydrogen on a large scale, the amount of byproduct carbon black produced from cracking methane would saturate the high use value markets. The rest might be sold as a soil amendment with properties similar to biochar — although its efficacy for that would need to be proven. However, there’s another scalable use that might be feasible: it might be used to fuel flexible power generation from direct carbon fuel cells.

Direct carbon fuel cells of various designs have been demonstrated, and there are ongoing efforts to commercialize them. Some approaches have shown efficiencies as high as 80% for electricity out to chemical potential energy in. But efforts have almost all been funded by DOE as part of its “clean coal” initiative. They’ve accordingly been directed at making the cells work using powdered coal as fuel. The impurities in coal have made that difficult. It’s possible that with a highly pure form of carbon black as fuel, commercial feasibility would be much easier to reach. If so, byproduct carbon black from methane cracking could become the ultimate stored energy resource. Stores of terawatt-hours of energy could easily be accumulated.

Of course, actually using carbon black as fuel for direct carbon fuel cells (DCFC) reintroduces the sequestration issue for the resulting CO₂ waste. But it’s a pure CO₂ waste stream, and the ease of transporting bulk carbon black means that the DCFC plants could be located close to CO₂ injection sites. If the DCFC approach works, it would be a way of shortcutting the CO₂ pipeline infrastructure problem.

Backing renewables

Regardless of whether methane cracking and possibly the DCFC approach to massive stored energy work out, it does seem to me that the idea of clean hydrogen from chemical processing of fossil fuels offers game-changing potential. The carbon or CO₂ waste streams can be sequestered at little cost — or negative cost in the case of CO₂ sold for EOR. That means that the hydrogen produced can truly be zero carbon, even before the power grid is decarbonized.

Most compelling, to me, is that $53 per kilowatt figure I mentioned last week as DOE’s estimate for the current system cost for PEM fuel cell stacks (in volume production). I’ve long held that the biggest problem with intermittent renewables is their effect on backing supplies. Under high penetration scenarios, backing supplies see short operating periods, fast ramp rates, and low overall duty cycles. That forces utilities to resort to the cheapest units they have to fill the role. Those are mostly simple combustion turbines that have high carbon emissions. However, $53 per kilowatt is even cheaper than simple combustion turbines. And PEM fuel cell stacks don’t care about operating periods or ramp rates. Their thermal efficiency compares to the best CCGTs, and doesn’t suffer from operation at partial capacity. They’re ideal!

The only problem is supplying them with enough hydrogen fuel. Electrolysis, as already noted, is too inefficient and too expensive. But when surplus RE is used to drive the endothermic SMR or methane cracking reactions, it yields more than a factor of ten more hydrogen than it would by electrolysis. One still has zero carbon fuel being made from cheap “as available” power, and thus the benefit of a “virtual battery” via control of power directed to the process. However, the degree of excess RE capacity needed to supply the fuel is drastically reduced.

I can imagine a whole host of issues and objections that are likely to be raised in response to my conclusion. Rather than trying to anticipate and address them all here, I think I’ll let them play out in the comments. Perhaps I’ll end up posting a subsequent column on the political and environmental issues around “zero carbon hydrogen” from fossil fuels. It will be a hot topic.

Editor’s note

Roger Arnold, systems architect at Silverthorn Engineering, is a former software engineer. He studied physics, math, and chemistry at Michigan State University’s Honors College , where he graduated in 1967. A US Army veteran (courtesy of the Viet Nam era draft), he later did graduate work in computer architectures and operating systems at the University of Colorado. Over the years, he has worked variously for IBM, Boeing Aerospace, AT&T, and about a dozen smaller companies and startups. Since retiring from professional life as a processor architect, he has refocused on clean energy technologies, energy efficiency, and space systems. His favorite activities are currently technical writing and mentoring early stage startups.

This article was first published on Energy Post’s sister publication The Energy Collective and is republished here with permission from the author.

About Roger Arnold

Comments

From a central European viewpoint, there is no EOR market for CO2, so significant scaling up of the methane reforming will require release of the CO2 or vigorous pursuit of sequestration, presumably (to minimize popular worries) with expensive pipelines to sub-seabed locations . The biggest issue for H2 use is seasonal storage, and the author’s simple calculations on the electricity cost of electrolytic H2 are valid. So I have trouble seeing near-term production beyond boutique levels at which one doesn’t worry about CO2 release (and small scale electrolytic production) This is one of several reasons that I regard the H2 fuel cell autos as playthings. I have considerable hopes that there will be real improvements in electrolytic H2 production over the next 20-30 years.

Anyone suggesting reformed methane as a future fuel source should be sent to their room without dinner.
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Hydrogen as an energy storage technology does work. Not well. As the author points out overall efficiency is about 40%.

I suggest we use Pump-up Hydro Storage (PuHS) as our comparison standard for long term energy storage. Overall efficiencies run from 70% to 85%. We might want to assume a number to the higher end of the range as any new installations should use the most efficient pumps and turbines.

Now, H2 would beat out PuHS if its overall cost was <50% of PuHS. We could afford to lose a lot of energy if we saved enough on infrastructure and operational costs.

I'm not sure it's possible to beat the cost of PuHS by more than 2x.

I don't think the author mentioned storage tanks for the hydrogen. If we couldn't find something like an underground cavern capable of storing H2 we'd be looking at some massive tanks. Hydrogen is very energy non-dense in terms of volume. Less than 10% the energy of a similar volume of gas/diesel.

The Swiss have claimed that they can build new PuHS if they can earn $0.05/kWh and the facility operates daily. Secretary Chu (?) said $0.10/kWh. I suspect we could convert one of thousands of existing dams and come out closer to the Swiss price.

That means that H2 storage cost (infrastructure, real estate, and labor) would have to be about $0.02/kWh or lower. For those of you who know something about electrolysis, compressors, storage tanks, and fuel cells – is that possible?

Large-scale hydrogen storage can be practical. As an example Northern Germany has massive salt deposits in which gigantic caverns can be dissolved out (or in some cases were excavated for salt in the past). They are already used for seasonal natural gas storage and could be adapted for hydrogen if large scale electrolysis works out. Current pumped hydro installations in central Europe are tiny compared to what would be needed for seasonal storage. On the other hand Norway claims a potential reservoir capacity of 84 TWh, although a significant build-out of this might be environmentally unacceptable. Both possibilities are very location dependent.

PuHS can also be built in abandoned rock quarries and mines. I believe there’s already work started to turn an old mine in Germany into a storage site.

Then, in NW Europe and in Switzerland there are lots of sites.

There’s no need for seasonal storage. What’s needed is filling in for a few days of low wind/solar. By strengthening connections across Europe those periods can be minimized.

If H2 can be cheaply stored in salt caverns that’s great. Do remember, H2 is harder to contain than larger molecules. But if leaking is not an issue then cost to generate and convert along with energy loss can be compared to other storage methods.

Seasonal storage is not to be dismissed as a matter of one or two days. What is more interesting is how much of it must support electrical generation and how much of it can be moved into heat storage. This obviously depends among other things on the extent to which district heating is developed or individual building heat pumps are used.

Anyone suggesting reformed methane as a future fuel source should be sent to their room without dinner.

Your opinion is noted, Bob. Now let’s talk about reality.

Unreformed methane, aka natural gas, is already a major fuel source. Since it emits only half the CO2 per unit of thermal energy as coal, some see it as a “bridge” to a decarbonized energy economy. Since available energy storage options aren’t up to the job, peaker units burning natural gas are currently about the best of a bad set of options to stand in for non-producing wind and solar resources. It doesn’t help that peaker units are much less efficient than the best combined cycle gas turbines. They burn 50 to 100% more gas per kWh of output. They still come out ahead of coal.

In contrast to that, reformed natural gas — aka hydrogen — can power fuel cells with efficiency comparable to the best CCGTs. Thanks to automotive development, the fuel cells are now at least as cheap as peaker units. They can ramp up and down mor quickly, and they don’t lose efficiency when operated at a fraction of rated capacity.

One other interesting point about gas reforming is that, as output from an endothermic reaction, the hydrogen produced has a higher free energy content than the natural gas from which it was produced. I can’t quote an exact figure offhand, but I believe the gain is on the order of 10%. What’s interesting is that when that heat is supplied by a well-designed solar furnace, the solar energy goes to added chemical potential energy at close to 100% efficiency.

What about carbon emissions? Well, in the really stupid worst case, when the pure CO2 waste stream from reforming is simply vented to the atmosphere, the combination of free energy gain and higher utilization efficiency means that carbon per kWh is still about 40% less than if natural gas had been burned in a simple peaker. In the best case, when the waste stream is permanently sequestered, carbon emissions are zero.

Regarding pumped hydroelectric storage, I happen to agree with you that it’s a better solution — in principle. But proposals for new pumped hydro have been advanced in various locations and shot down. It seems that local voters tend to object to building new dams and flooding scenic valleys with reservoirs. Something better will have to be developed.

I’m one who sees natural gas as a bridge to a carbon free (or at least very low carbon) energy future. I don’t see it in the sense of a bridge constructed to last decades, but more like a pontoon bridge put together for short term use.

Since it’s a short term assist we should spend as little as possible and devote our resources to building long term solutions.

(And I do appreciate reality.)

Let’s establish a basic fact up front. Whatever we do that is different from what we are now doing will require new infrastructure. Whether that infrastructure is H2 extraction/compression plants, energy storage facilities, or whatever, new stuff will be built. Money will be spent on it. It will take time to build.

Now, let’s think out our options.

1) Reforming methane with carbon sequestering and using fuel cells to produce electricity.

We have a limited amount of natural gas underground. This would be, at best, a short term solution. Not a solution for the next 100 years. We’d need to keep drilling and fracking gas wells, build hydrogen extraction plants. Create hydrogen storage facilities. Manufacture and install fuel cells. And figure out where and how to sequester the carbon.

At this time our CO2 sequester solution is to pump it down oil wells to force out reluctant oil. The needs are limited. Many countries have no ongoing oil industries who want CO2. The coal plant with CCS built in Canada had to be downsized to 20% of its original design because there was no demand for more CO2.

2) Continue to burn natural gas directly in CCNG plants.

The secondary steam part of combined cycle plants add about 40% more electricity to the production but take up to three hours to reach speed after the turbine begins to operate. Many grids already have CCNG installed so there would be no further investment required. And if they are needed their installed cost is very low.

The solution to the energy lost during heat up and cool down is to run fewer CCNG plants and run them continuously for long periods of time when we need them. Don’t use them as dispatchable generation called on when demand rises, turning them on at noon and off at 7PM.

Use storage for short term variation between supply and demand. Build storage now for the vast majority of time in which we can get all the electricity we need from renewables over a few (2-3?) days. The number of days will grow as storage prices fall.

When the weather forecasters signal an unusually low period of renewable input which would exceed the energy we have in storage start up a few CCNG plants. Just enough to make up for the missing renewables. When demand drops low (late night) send the CCNG output to storage. Then use that stored energy to meet higher demands. Don’t waste energy by turning CCNG plants on and off.

Aside from the storage, which we must build anyway, there would be no cost. The gas infrastructure is in place. Many grids could probably retire their peakers. Mothball them for possible emergencies. Run their CCNG plants less, cycle them less often, thus extending their useful life.

Long term, we may need a small amount of thermal backup. We could run CCNG plants using biogas for those few hours a year our grid supplies are highly stressed.

3) The long term solution. Energy storage. With, perhaps, some thermal deep backup.

This is where we will have to go. Wind and solar will always be variable as will demand. Storage allows us to match supply to demand. Spend money building storage now rather than spend on a short life reformed methane system.

At the moment pump-up hydro storage is our least expensive way to store large amounts of energy for extended periods of time. Batteries have apparently reached cost parity with PuHS for short duration storage.

Battery prices will almost certainly continue to fall. Batteries will be the least expensive way to move late night wind to mornings and daytime solar into early evening. And the least expensive way to move Monday’s sunshine to Tuesday and Wednesday. We may never reach the point where batteries are the least expensive way to move energy from week to week or March to August. That’s the role of PuHS.

Since we need to spend money now, build PuHS. It can serve for both short and long cycle storage. The pumps and turbines can be used every day. Make the reservoirs large enough to store energy for long periods of low wind/solar.

Install, as we are doing, batteries to smooth grids. To suck up supply peaks and supply demand spikes. That’s already being done because the numbers work. And we’re starting to see larger amounts of batteries added for time-shifting electricity.

There’s no shortage of places to install PuHS. The US has thousands of existing dams that can be converted. That’s probably the case in most countries. Abandoned open pit mines, subsurface mines, and rock quarries are other “already spoiled” sites where we can find abrupt changes in elevation and ample room to install storage.

US southern states are blessed with year round sun. Solar capacity factors are around 20%. Diurnal battery and solar PV systems are economic and feasible such that off grid is a reality.
Northern Europe is very different with 10% solar CF and extended low wind and dark winter periods lasting many days. To deal with this 100s of new pumped storage stations would be needed at around $4bn each and extensive transmission reinforcement. Feasible sites are limited and there are environmental issues too. Why ignore safe new nuclear which achieves 90% CF? Trying to achieve a near 100% renewables dream using pumped storage and batteries only appeals to those who are ideologically opposed to new nuclear.
BTW CCGTs can be engineered to fast start in open cycle mode to hit peaks. No need to run the steam cycle for short periods of operation. They can be engineered for baseload, or just peak operation.

I’ll try to answer in more detail at the outer level. That’s partly because the column width for deeply nested comments gets awkwardly narrow, and partly because the issues involved are general — and IMO, important.

I will say that we appear to be aligned on ultimate goals; it’s at the level of strategy and tactics where we differ. And in our perceptions about costs and economic viability.

US southern states are blessed with year round sun. Solar capacity factors are around 20%. Now diurnal battery and solar PV systems are economic and feasible such that ‘off grid’ is a reality now.
However northern Europe is very different with 10% solar CF and extended low wind and dark winter periods lasting many days. To deal with this 100s of new pumped hydro storage stations would be needed at around $4bn each and extensive transmission reinforcement. Feasible sites are limited and there are environmental issues too.
In the US only some existing reservoirs would be suitable for PS. A lower reservoir would need to be built and grid scale machines installed. Battery systems help maintain grid stability but their endurance is short at full output, only hours not days.
This all begs the question why list options and completely ignore safe new nuclear which achieves 90% CF? Phasing out nuclear power is only happening in some countries. It’s not happening in the US, and Canada is restoring their CANDU units to operation as it is economic and very effective reducing carbon emissions.
Trying to achieve a near 100% renewables dream using pumped storage and batteries really only appeals to those who are ideologically opposed to new nuclear.

Roger, I appreciate your balanced analysis. Let the fossil free technologies develop and mature side by side.
In Northern Europe, which has a transnational grid cooperation, wind electricity is sometimes abundant. It drives down electricity cost below 0, i.e. a negative price. If some of this surplus electricity is used for hydrogen production the cost of that hydrogen will be low, not totally free, but certainly lower than for fossil fuels. This hydrogen can be used for energy storage and to drive cars, airplanes, drones, trucks etc. The simple truth is that FC and hydrogen sometimes outperform battery alternatives.

This is a followup on issues raised by Bob Wallace regarding use of SMR to produce hydrogen for backing renewables. It also considers the merits of that approach vs. pumped hydroelectric storage.

I should preface this by noting that I reside in the US, and that does admittedly color my views. Natural gas is cheap and the consensus is that it will remain so for quite some time. Carbon capture and storage is likely easier here, as there are a lot of mature oil and gas fields here that could store CO2 securely, as well as extensive deep saline reservoirs. I understand that gas is less prevalent in Europe, and that much of what’s used must be imported from Russia. CCS may be more problematic — both geographically and politically.

One other big difference between the US and Europe is cultural. Europeans appear to be more tolerant of policies imposed by administrative fiat, so long as there’s a green rationale. Something like Germany’s Energiewende would be unthinkable in the US. The idea that “the cheapest wins” is firmly in the saddle, and solutions that would end up raising costs to consumers generally “need not apply”. I don’t always like that outlook, but I understand the distrust of bureaucrats that feeds it. I choose to see the need to plot solution paths that are “downhill runs” in cost/feasibility space as a useful discipline.

That’s very abstract, and may already have turned some readers off. So here’s a concrete example: pumped hydroelectric energy storage.

Pumped hydro Is the most widely implemented and cost-effective approach currently available for large scale energy storage. There’s more that could be built, especially if new technologies for tunneling and reservoir construction were employed. But despite an acknowledged need for stored energy to fill in for temporarily non-producing wind and solar resources, pumped hydro projects are not getting built. Even some that have been built are struggling financially. They’re hard-pressed to cover operating expenses by rate arbitrage. Why is that?

The principal reason, I believe, is that as things stand, it’s cheaper and easier to fire up a peaker unit when needed. They’re not very efficient and have high carbon emissions, but at least in the US, there’s no penalty for that. The cheapest wins, and despite lip service to reducing carbon emissions, burning carbon remains the cheapest way to provide dispatchable power. Europe isn’t actually much better, with the pricing for carbon credits a joke.

Pumped storage projects, and to some extent the long distance transmission projects that underpin green visions of a fully renewable energy economy, share some of the same handicaps as nuclear power. The permitting process is long and treacherous, with the focused interests of NIMBY and ideological opponents often triumphing over the diffuse interests of casual supporters. If and when the court challenges and legal fees are put to rest, construction will still tie up capital for a protracted period before any revenue is generated. Not the most appealing business prospect.

It’s against that background that I would argue for using SMR to produce hydrogen for stabilizing the grid. That’s how more than 95% of hydrogen used in industry is made, and the product is far less expensive than electrolytic hydrogen. The high efficiency of fuel cells compared to diesel engines or simple combustion turbines means that reforming would reduce the amount of natural gas consumed. Most importantly, it would get carbon-free backing resources quickly in place and integrated into the grid. Those resources are what matter, and they don’t care how the hydrogen fueling them was produced. The capital cost of SMR equipment is low, and SMR does not “lock in” a dependence on natural gas in the long term. Hydrogen from SMR can be replaced or supplemented by electrolytic hydrogen at any time it’s economical.

Making the CO2 waste stream from SMR operations available for EOR operations, at least in the US, has strategic value for decarbonizing. The infamous “fossil fuel interests” that have stymied all efforts so far to impose a meaningful price on carbon emissions understand quite well that the sun is setting on oil. The specter of “stranded assets” stalks them. That’s why oil has gotten so cheap. At this point, a battle of interests is shaping up between the holders of mature conventional resources and those pursuing new resources through horizontal drilling and fracking tight formations. The former now have more to gain than lose from a carbon tax. Since the tax would presumably apply equally to all producers, it would not disadvantage them in the market. And it would help them — a lot! — by allowing them to tap a revenue stream for sequestered carbon, while boosting production from their mature fields.

Dear Roger, first of all I would like to thank you for the article. I appreciate your comprehensive approach very much. I would like to refer to your statements/analysis regarding “Thermal cracking of methane into Hydrogen”. Prof. Carlo Rubbia – a Nobel prize winner – published an article in ELSEVIER dealing with this topic – including some costs estimation (Title: Thermal Cracking of methane into Hyxrogen for a CO2-free utilization of natural gas) in 2012. Prof. Rubbia made a presentation on this issue at the Academy of Science in Vienna in January 2017. So, I wonder why there is not more interest in this promising technology from the gas producing countries, gas suppliers, gas infrastructure operators, fuel cell producers and – last but not least – automotive industry. They should raise the required money for a relatively quick development of this technology, which – from my humble opinion – could deliver the urgently needed quick wins. I also had the chance to visit the so called Big sight in Tokyo in February this year. At this exhibition one could see the latest developments regarding fuel cells (stationary as well as mobile applications), hydrogen. Besides information was given (of course not in details) on the ongoing research regarding hydrogen fuelled turbines (by Mitsubishi). It is unbelievable how much research is ongoing in Japan, South Korea and in the meantime in China. I assume it might be worthwhile to promote the “thermal cracking process”. The idea to use excess electricity to produce hydrogen is simply too expensiv. Besides the fact that there is no definition what excess electricity might be, the period in which the price for electricity is minus, did amount to roughly 200 hours per year in the last few years. This is by far too low to allocate the massiv CAPEX to a high number of cost units – which is kg hydrogen – to achieve affordable prices/costs. One would need a very high workload per year (the higher the better) but this is simply not given because of the low number of hours in which the electricity generates revenues (negative price). Besides the number of hours in which the price for electricity is negative is decreasing because of the increasing flexibility of the generators (and other systemic impacts). Even if the amount of hours in which electricity generates negative prices were not decreasing, an increasing demand for electricity would certainly higher the prices for the commodity electricity, thus generate the demand for more RES, finally increasing the required subsidies (there is no such thing like grid parity if the current price discovery mechanismus is not replaced by another system). Looking forward to your answer.

There is a basic error in the assumption about electricity supply systems. It is not written there, but it remains in the back of the assumptions on which writing was started. It says that the existing park of power plants, and also in a future park of renewable generation, has a size to provide 100,000% of demand. Not more not less. This is a faulty assumption, since demand changes year by year, and plant maintenance keems unkonwn numbers of plants from the market every year.
Which results in the fact, that the park of power plants in a stable grid today is always able to supply 110-130% of demand, depending on the risk adversion of the country.
This will not change if a country switches to renewable power production.
So although there is a possibility of low supply during short times when power is provided by wind, solar, hydro and biomass in huge grids, during nearly all other times there will be a more or less huge amount of surplus power during the rest of the time.
(different from today, the plants will not stay idle, but produce power at close to zero variable costs)
The question will be for which purposes this power will be used.
Most likely to produce raw materials which can be stored. Potable water in arid countries for example. Aluminium and other metals for example. And if electrolysis equipment can be made cheap surely also to produce raw materials for the chemical industry, based on H2 oand CO2. A part of this stram can be deviated for backup power generation. Backup power generation has the characteristic, that it is used for few hours only. So the capacity costs matter, not the energy costs. So most likely fuel for this will be stored as liquid, which provides lowest capacity costs, and not as H2.
I do not see any base to assume 25 or more % of power being produced from H2. This would only happen if grids are switched off. Which is not a likely scenario.